Fractured Shale Gas Reservoirs Research Articles

Fracture path interaction of two adjacent perforations subjected to different injection rate increments

During the fracturing of shale gas reservoirs, the injection rate and its variation affect the fracture propagation path and fracture connectivity between two adjacent perforations. To reveal the interaction mechanism of injection rate change on hydraulic fracture propagation of adjacent perforations, an extended finite element method (XFEM) was employed for simulating the fracture propagation and interactions between adjacent hydraulic fractures under different injection rate increments. Considering the heterogeneity of rock minerals and based on the results of shale mineral composition analysis via X-ray diffraction (XRD), a code segment was written in Python to establish a computational network model with a random distribution of different material properties. Acoustic emission (AE) data extraction and fracture location during the process of fracture propagation were realised using MATLAB programming. Simulation results revealed that the closer the injection rate increments in adjacent perforations, the greater the compressive stress between the perforations. Variations in the pressure difference and fracture width difference between the two perforations dynamically reflect their interactions; both anisotropy and stress shadow determine the fracture propagation path. This study provides a good technical basis for fracture design optimisation.

Hydrodynamic Equilibrium Simulation and Shut-in Time Optimization for Hydraulically Fractured Shale Gas Wells

Post-fracturing well shut-in is traditionally due to the elastic closure of hydraulic fractures and proppant compaction. However, for shale gas wells, the extension of shut-in time may improve the post-fracturing gas production due to formation energy supplements by fracturing-fluid imbibition. This paper presents a methodology using numerical simulation to simulate the hydrodynamic equilibrium phenomenon of a hydraulically fractured shale gas reservoir, including matrix imbibition and fracture network crossflow, and further optimize the post-fracturing shut-in time. A mathematical model, which can describe the fracturing-fluid hydrodynamic transport during the shut-in process, and consider the distinguishing imbibition characteristics of a hydraulically fractured shale reservoir, i.e., hydraulic pressure, capillarity and chemical osmosis, is developed. The key concept, i.e., hydrodynamic equilibrium time, for optimizing the post-fracturing shut-in schedule, is proposed. The fracturing-fluid crossflow and imbibition profiles are simulated, which indicate the water discharging and sucking equilibrium process in the coupled fracture–matrix system. Based on the simulation, the hydrodynamic equilibrium time is calculated. The influences of hydraulic pressure difference, capillarity and chemical osmosis on imbibition volume, and hydrodynamic equilibrium time are also investigated. Finally, the optimal shut-in time is determined if the gas production rate is pursued and the fracturing-fluid loss is allowable. The proposed simulation method for determining the optimal shut-in time is meaningful to the post-fracturing shut-in schedule.

Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume

Optimization of multi-stage fracturing horizontal wells is with great significance in shale oil and gas reservoir production to enhance the gas recovery. The stimulated reservoir volume (SRV) is an important factor for fracturing horizontal well design and gas reservoir development. However, very few research has studied horizontal well optimization considering the effect of SRV. This paper proposes a mathematical model for SRV estimation during hydraulic fracturing. The model couples both rock and fluid mechanic effects. The displacement discontinuity method (DDM) is adopted to calculate the formation stress field. Then a natural fracture failure criterion based on formation pressure and stress fields is used to estimate the SRV. Additionally, a stress dependent permeability (SDP) algorithm is applied to estimate permeability change within the SRV region. Based on SRV and SDP models, an automatic optimization framework is established, with the net present value (NPV) employed as the optimization objective function, in which the overall cost and the ultimate income are involved simultaneously. A Modified-PSO algorithm is proposed and adopted to realize the optimization process, which can significantly reduce the calculation time while maintaining the accuracy of the result. In the end, two cases with shale gas reservoirs are presented, and different types of hydraulic fracturing wells are optimized to validate this optimization framework. Parameters including hydraulic fracturing spacing and half-length, well spacing and well length are optimized to achieve the optimum well design. The optimization results are compared and discussed, which show that this approach can contribute to obtaining the optimal shale gas recovery and provide a new insight into hydraulic fracturing well design under the effect of SRV.

Analytical solutions for multi-stage fractured shale gas reservoirs with damaged fractures and stimulated reservoir volumes

After performing hydraulic fracturing in shale reservoirs, the hydraulic fractures and their adjacent rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures; (2) partially propped fractures with unpropped or poorly propped sections at the middle or tail of fractures; (3) fracture face damage; and (4) multiple damage cases. The classical fracture skin factors are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple damage and partially propped fractures. In this article, a new analytical model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs.The matrix model is a spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly envelops the matrix. The reservoir-fracture flow model is a ten-region linear flow model which can handle fracture damage mechanisms. Specifically, the inner reservoir region is treated as an SRV where the secondary fracture permeability obeys a power-law decreasing trend due to the attenuate stimulation intensity.This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of a published linear flow model. New type curves are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Different damage mechanisms all control specific flow regimes but the fracture face damage shows the slightest influence. In the multiple fracture damage case, some typical flow regimes can be easily identified except those induced by the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.

Determination of Hydraulic Properties of a Large Self-Propped Hydraulic Fracture in the Geothermal Research Borehole Horstberg Z1 in the Northwest German Basin

The pressure records of an interference test on a huge hydraulic fracture in a layered sedimentary rock formation of the Northwest German Basin were analysed in order to determine fracture transmissivity and fracture storage coefficient. The fracture had been created by injecting some 20,000 m3 of freshwater at 3800 m depth in borehole Horstberg Z1 of the geothermal research project GeneSys. Its main purpose is to study the hydraulic properties and mechanical behaviour of artificial fractures kept open by the so called self-propping effect which results from the misfit of the opposite fracture surfaces being sheared during fracture propagation. A diagnosis of the pressure records of the interference test showed that the flow geometry is parallel (vertical linear fracture flow) rather than radial or bilinear. This is explained by assuming a highly conductive flow channel within the fracture resulting from a turn of tensile to mixed-mode fracture propagation. Based on this observation an analytical 1D-model was developed that describes transient fluid-flow in a vertical fracture that is imbedded in impermeable rock and is vertically confined by permeable rock layers. This model was verified by a corresponding 1D-numerical model and was then used to fit the observed pressure records of the constant rate interference test. The fitting procedure yielded a transmissivity of the self-propped fracture in claystone that is more than ten times lower than the transmissivity of self-propped fractures in granite as observed in HDR/EGS systems (Hot-Dry-Rock/Enhanced Geothermal Systems). At the same time it is more than ten times higher than the transmissivity of propped fractures in shale gas reservoirs. The injectivity index of the studied fracture resulting from transmissivity and the high length to height ratio of the fracture enables to circulate water or brine through the fracture at flow rates up to about 0.005 m3/s. For the given temperature of about 150°C this would satisfy the heat demand of small to medium size building complexes. Higher flow rates and heat production could be achieved with multiple fractures of this kind. The results obtained in borehole Horstberg Z1 are promising but more in-situ experiments in various rock formations and different stress regimes are necessary to generalize the results.

Water-Gas Two-Phase Flow Behavior of Multi-Fractured Horizontal Wells in Shale Gas Reservoirs

Hydraulic fracturing is a necessary method to develop shale gas reservoirs effectively and economically. However, the flow behavior in multi-porosity fractured reservoirs is difficult to characterize by conventional methods. In this paper, combined with apparent porosity/permeability model of organic matter, inorganic matter and induced fractures, considering the water film in unstimulated reservoir volume (USRV) region water and bulk water in effectively stimulated reservoir volume (ESRV) region, a multi-media water-gas two-phase flow model was established. The finite difference is used to solve the model and the water-gas two-phase flow behavior of multi-fractured horizontal wells is obtained. Mass transfer between different-scale media, the effects of pore pressure on reservoirs and fluid properties at different production stages were considered in this model. The influence of the dynamic reservoir physical parameters on flow behavior and gas production in multi-fractured horizontal wells is studied. The results show that the properties of the total organic content (TOC) and the inherent porosity of the organic matter affect gas production after 40 days. With the gradual increase of production time, the gas production rate decreases rapidly compared with the water production rate, and the gas saturation in the inorganic matter of the ESRV region gradually decreases. The ignorance of stress sensitivity would cause the gas production increase, and the ignorance of organic matter shrinkage decrease the gas production gradually. The water film mainly affects gas production after 100 days, while the bulk water has a greater impact on gas production throughout the whole period. The research provides a new method to accurately describe the two-phase fluid flow behavior in different scale media of fractured shale gas reservoirs.

Mechanism of fracture damage induced by fracturing fluid flowback in shale gas reservoirs

In this paper, the Lower Silurian Longmaxi shale samples and the backflow fracturing fluid in the Changning Block of the Sichuan Basin were selected to investigate the damage mechanism of retained fracturing fluid to fractures in shale gas reservoirs. Thus, experiments were conducted on fracturing fluid backflow and gas-driving fracturing fluids. The changes of liquid permeability of shale samples, solid particle size distribution and turbidity of the backflow fracturing fluid were monitored. The gas permeability before and after fracturing fluid gas drive was compared, and the damage degree and mechanism of the backflow fracturing fluid to the fractures in shale samples were analyzed. And the following research results were obtained. First, the damage rate of shale permeability after the fracturing fluid backflow is between 53.1% and 97.6%, and the range of the solid particle size of the flowback fluid is significantly reduced. The main reservoir damage modes include phase trapping damage caused by liquid phase retention, blockage caused by the solid phase residue, particle migration induced by gas-carrying liquid and salt precipitation. Second, in the stage of gas phase flow, the damage rate of permeability drops to 23.1–80.2%, and the damage caused by liquid phase retention is relieved, but the damage caused by the blockage of solid phase residue and the salt precipitation of flowback on the facture surface is inevitable. Third, based on the damage mechanism of fracturing fluid backflow in shale gas wells to fractures, considering the treatment difficulty of the flowback and its damage to reservoir fractures, it is recommended to give a full play to the fracturing capacity of fracturing fluid and optimize the properties and dosages of fracturing fluid so as to reduce the flowback of fracturing fluid as much as possible.

Production forecast of a multistage fractured horizontal well by an analytical method in shale gas reservoir

Industry benefits cannot be obtained from shale gas reservoir without stimulations, due to the ultra-low porosity and permeability of shale. A series of integrated technical measures have been developed for developing shale gas economically, such as horizontal wells and multistage hydraulic fracturing. Combining the above works, we can achieve higher productivity by enlarging stimulated reservoir volume (SRV) and linking fracture network in shale gas reservoirs. In this paper, a novel analytical mathematical model for production forecast of multistage horizontal well was developed based on the seepage theory of fractured well in the dual-medium gas reservoirs. In this model, multi-scale migration mechanism and the complicated morphology of hydraulic fractures in fractured shale gas reservoir were considered. It has been closely solved by the method of well test analysis and mathematical physics. To validate the accuracy of the model in this paper, a well from Changning–Weiyuan shale gas reservoir in China is taken as a real-case application. The calculation results of the model and the actual production data of the well are in good accordance. Meanwhile, the impacts of sensitive factors including desorption, Knudsen diffusion, slip flow, stress sensitivity of micro-fractures and high-velocity non-Darcy flow within hydraulic fractures on cumulative production were analyzed. At last, fracture morphology has been optimized through the model.

A Multiscale Fractal Transport Model with Multilayer Sorption and Effective Porosity Effects

In order to study gas transport properties of fractured shale gas reservoirs for the accurate estimation of shale gas production, a new multiscale fractal transport model with an effective porosity model was proposed based on the fractal theory and the multilayer fractal Frenkel–Halsey–Hill (FHH) adsorption. In shale matrix, both fractal microstructures of pores (such as pore size distribution, flow path tortuosity, and pore surface roughness) and multiscale flow mechanisms (including slip flow and Knudsen diffusion) were coupled. In fracture network, fractal fracture length distribution, stress compaction, and gas pressure were introduced to formulate a new fracture permeability model. These permeability and effective porosity models were then incorporated into the governing equations of gas flow and the deformation equation of reservoirs to form a numerical model. This numerical model was solved within COMSOL Multiphysics for shale gas recovery. Both transport models in shalematrix and fracture network were validated by experimental data or compared with other models. Finally, sensitivity analysiswas conducted to identify key parameters to gas recovery enhancement. Itwas found that themultilayer gas adsorption and fractal microstructures have great impacts on gas production in shale reservoirs. The cumulative gas production can be increased by 26% after 8000 days when themultilayer adsorbed gas is considered. Larger surface fractal dimension and larger tortuosity fractal dimension represent more roughness pore surface, higher flow resistance, and lower cumulative gas production. Bigger pore diameter fractal dimension means more pores, higher permeability, and higher cumulative gas production. Our model with fractal FHH adsorption was in better agreements with field data from Marcellus and Barnett shale reservoirs than other models.

Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures

Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.

IMPACTS OF ZONE FRACTAL PROPERTIES ON SHALE GAS PRODUCTIVITY OF A MULTIPLE FRACTURED HORIZONTAL WELL

A multiple fractured shale gas reservoir is divided into three zones, namely the single-porosity zone, the dual-porosity zone, and the hydraulic fracture zone. The distributions of pore size, fracture length, and fracture aperture vary in each zone and affect shale gas productivity. This paper developed a fractal numerical model to investigate the impacts of zone fractal properties on the shale gas productivity of a multiple fractured horizontal well. In this model, a fractal permeability model was developed, in which the diameter/aperture distribution of circular/slit pores and the length of fractures all follow fractal scaling law. This numerical model was solved by finite element method within the platform of COMSOL Multiphysics and verified through the history matching of production data from the Marcellus and Barnett shale reservoirs. Finally, the effects of the fractal dimension ([Formula: see text], [Formula: see text], [Formula: see text]) and the maximum diameter ([Formula: see text]) of the pores on gas productivity (measured by gas production rate and cumulative gas production) were investigated. Numerical results show that increasing the maximum pore diameter [Formula: see text] can enhance gas productivity, but increasing the pore diameter fractal dimension [Formula: see text] makes the gas productivity decrease and increasing tortuous fractal dimension [Formula: see text] decreases the gas productivity, too. The length fractal dimension [Formula: see text] of fractures is sensitive to the gas flow in the dual-porosity zone.

Numerical Simulation of Artificial Fracture Propagation in Shale Gas Reservoirs Based on FPS-Cohesive Finite Element Method

The simulation of hydraulic fracturing by the conventional ABAQUS cohesive finite element method requires a preset fracture propagation path, which restricts its application to the hydraulic fracturing simulation of a naturally fractured reservoir under full coupling. Based on the further development of a cohesive finite element, a new dual-attribute element of pore fluid/stress element and cohesive element (PFS-Cohesive) method for a rock matrix is put forward to realize the simulation of an artificial fracture propagating along the arbitrary path. The effect of a single spontaneous fracture, two intersected natural fractures, and multiple intersected spontaneous fractures on the expansion of an artificial fracture is analyzed by this method. Numerical simulation results show that the in situ stress, approaching angle between the artificial fracture and natural fracture, and natural fracture cementation strength have a significant influence on the propagation morphology of the fracture. When two intersected natural fractures exist, the second one will inhibit the propagation of artificial fractures along the small angle of the first natural fractures. Under different in situ stress differences, the length as well as aperture of the hydraulic fracture in a rock matrix increases with the development of cementation superiority of natural fractures. And with the increasing of in situ horizontal stress differences, the length of the artificial fracture in a rock matrix decreases, while the aperture increases. The numerical simulation result of the influence of a single natural fracture on the propagation of an artificial fracture is in agreement with that of the experiment, which proves the accuracy of the PFS-Cohesive FEM for simulating hydraulic fracturing in shale gas reservoirs.

Investigation on Interference Test for Wells Connected by a Large Fracture

Pressure communication between adjacent wells is frequently encountered in multi-stage hydraulic fractured shale gas reservoirs. An interference test is one of the most popular methods for testing the connectivity of a reservoir. Currently, there is no practical analysis model of an interference test for wells connected by large fractures. A one-dimensional equation of flow in porous media is established, and an analytical solution under the constant production rate is obtained using a similarity transformation. Based on this solution, the extremum equation of the interference test for wells connected by a large fracture is derived. The type-curve of pressure and the pressure derivative of an interference test of wells connected by a large fracture are plotted, and verified against interference test data. The extremum equation of wells connected by a large fracture differs from that for homogeneous reservoirs by a factor 2. Considering the difference of the flowing distance, it can be concluded that the pressure conductivity coefficient computed by the extremum equation of homogeneous reservoirs is accurate in the order of magnitude. On the double logarithmic type-curve, as time increases, the curves of pressure and the pressure derivative tend to be parallel straight lines with a slope of 0.5. When the crossflow of the reservoir matrix to the large fracture cannot be ignored, the slope of the parallel straight lines is 0.25. They are different from the type-curves of homogeneous and double porosity reservoirs. Therefore, the pressure derivative curve is proposed to diagnose the connection form of wells.

A fully coupled fracture equivalent continuum-dual porosity model for hydro-mechanical process in fractured shale gas reservoirs

A fully coupled fracture equivalent continuum-dual porosity model is proposed to investigate hydro-mechanical coupling phenomena in fractured porous media. An improved fracture tensor is then developed to transform the local discontinuities at cell level to the anisotropic continuum at macro-scale. This model is incorporated into a set of nonlinear partial differential equations and numerically solved by multi-time-step finite element algorithm. The approach is then applied to a field-scale simulation of shale gas reservoir. Results indicate that the proposed method can be applied to insights into the field-scale hydro-mechanical coupling with high-density fractures in any arbitrary orientation within manageable computational cost.

Proppant-packed fractures in shale gas reservoirs: An in-situ investigation of deformation, wettability, and multiphase flow effects

The results of a systematic, micro-scale experimental investigation on two-phase gas/brine flow through proppant-packed fractured shale samples under increasing effective stresses of up to 5000 psi are presented in this paper. We use a miniature core-flooding apparatus integrated with a high-resolution X-ray micro-CT scanner to perform the flow experiments. Geomechanical deformation and its impact on displacement mechanisms governing fluid transport within the packed fractures are studied at the pore scale under certain flow and stress conditions. These conditions were carefully designed to represent reservoir depletion and transport of water through such media. Since proppant grains are placed to maintain the long-term conductivity of the induced fractures, they significantly influence the geomechanical and multi-phase flow behavior of these conduits during reservoir depletion. We particularly examined the effectiveness of modified resin-coated sand (compared to a basic white sand) in maintaining the hydraulic conductivity of induced fractures. Significant bullet-like embedment and proppant crushing under severe stress conditions were found to be the shortcomings of these proppants, respectively. We then developed a methodical framework to design improved proppants with a similar mechanical strength to the host shale rock to withstand these drawbacks.Sphericity, roundness, and size of the proppant grains also impacted the critical properties of the constructed pore space such as pore size distribution and pore-throat aspect ratio. Such parameters control pore-scale gas-to-brine and brine-to-gas displacements within the hydraulic fractures. We specifically studied the non-wetting phase trapping and its subsequent impact on reduction of available pore space for other fluids to flow. It was found that trapped gas globules are very likely to deform within the medium and redistribute/reconnect under a higher effective stress. For the first time, wettability alteration of the proppant pack from water-wet to oil-wet was observed in a gas/brine fluid system. Wettability alteration occurred non-uniformly and was thought to be due to deposition of the shale organic matter released after significant proppant embedment. Such wetting characteristics aggravate multi-phase trapping within the fractures, which in turn leads to dramatic reductions in effective gas permeability. This study is concluded with a set of recommendations that can be used to effectively maintain the productivity of propped fractures for extended period of time.

Construction of a 3D Geomechanical Model for Development of a Shale Gas Reservoir in the Sichuan Basin

SummaryCurrently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.

Multi-scale modeling of shale laminas and fracture networks in the Yanchang formation, Southern Ordos Basin, China

Outcrops and core observations show that sandy and tuffaceous laminas and natural fractures are well developed in the continental shale gas reservoir. This study reports the distribution of laminas and natural fracture networks at different scales, in cases of outcrops, wells and cores from Yanchang Formation, southern Ordos Basin. Firstly, based on two-dimensional fracture field investigations, a 3-D joint network model of the study area was built using the Monte Carlo simulation method. Then the laminations were identified from macroscopic scales to microscopic scales with multiple probe techniques. Statistical analysis of multi-scale layer thickness suggested that the average thickness of layers at multiple scales showed a fractal feature, and that the layer thickness at each scale followed with an exponential probability distribution, whose exponential coefficient was −3.38, −1.91, −1.65, −1.21, corresponding to meter scale, decimeter scale, centimeter scale and millimeter scale respectively. The fitting curves indicated that the majority of laminas at each scale were relatively thin, and the thicker the layer, the less the number of layers contained in shale. Finally, the lamination models were constructed and superposed over the joint network model to generate 3-D geological structure models at various scales. The models were validated by reproducing fracture and lamina parameters fairly close to those obtained from realistic geological bodies in the study area. The findings of this work could provide a more reliable geological model for the numerical simulation and physical model test of hydraulic fracturing in shale gas reservoir.

Effects of ‘soft-hard’ compaction and multiscale flow on the shale gas production from a multistage hydraulic fractured horizontal well

In this study, the shale gas production from a multistage hydraulic fractured shale gas reservoir was analyzed. Firstly, the reservoir was divided into single-porosity medium zone, dual-porosity medium zone, and hydraulic fracture zone. Then, a mathematical model was established for the multiscale gas diffusion and adsorption/desorption mechanisms in matrix, the gas flow in fractures and the interaction between gas flow and shale deformation. Thirdly, this mathematical model was numerically solved within the platform of Comsol Multiphysics and verified by the history matching of the gas production data from Barnett and Marcellus shale reservoirs. Finally, sensitivity study was conducted to identify key parameters to the efficiency of gas recovery enhancement. It is found that hydraulic fracture aperture and initial permeability of fractures are positively correlated with gas production rate. The ‘soft – hard’ compaction of fractures can significantly modify gas production rate but the modification varies with gas production stage. The deformation and flow properties of hydraulic fractures have significant impacts on gas production rate, particularly in the early stage.

Analytical investigation of hydraulic fracture-induced seismicity and fault activation

More recent public discourse has taken place regarding the potential correlation between seismic activity and hydraulic fracturing in shale gas reservoirs. Public fears about the risk of seismicity stem mainly from past earthquakes induced by conventional deep injections because the two types of projects share similar mechanisms of rock failure and fault activation. Although previous earthquake risks associated with fluid injection were not serious, the situation would be far more problematic if hydraulic fracturing in a shale gas reservoir triggered a similar-sized earthquake due to potential environmental issues. In fact, almost all documented injection-induced earthquakes have been associated with long-duration and high-volume injection rather than short-term (hours) pressurization (e.g., hydraulic fracturing). In general, hydraulic fracturing operations mostly induce microseismic events through rock failure and activation of small fractures. Although shale reservoirs in tectonically active zones pose a high risk of inducing large-magnitude seismic activities, the internal geological conditions and external stimulation conditions are impossible to be satisfied simultaneously to trigger activation of an entire fault and to result in a destructive earthquake during hydraulic fracturing operations.

A Fully Coupled Numerical Model for Microwave Heating Enhanced Shale Gas Recovery

Formation heat treatment (FHT) can be achieved by converting electromagnetic energy into heat energy (that is microwave heating or MWH). Experimental evidence shows that such FHT can significantly enhance oil and gas recovery. As relatively few research studies have been reported on microwave heating enhanced shale gas recovery (MWH-EGR), a fully coupled electromagnetic-thermo-hydro-mechanical (ETHM) model is developed for the MWH-EGR in the present study. In the ETHM model, a thermal-induced gas adsorption model is firstly proposed for shale gas adsorption and fitted by experimental data. This thermal-induced adsorption model considers the increase of matrix pore space due to the desorption of the adsorbed phase. Further, a thermal-induced fracture model in shale matrix is established and fitted by experimental data. Finally, this ETHM model is applied to a fractured shale gas reservoir to simulate gas production. Numerical results indicated that the thermal-induced fracturing and gas desorption make predominant contributions to the evolution of matrix porosity. The MWH can increase cumulative gas production by 44.9% after 31.7 years through promoting gas desorption and matrix diffusion. These outcomes can provide effective insights into shale gas recovery enhancement by microwave assistance.